Techniques for the operation of gas wells producing from petroleum reservoirs vary substantially not only from geologic region to region but also among wells producing from a given reservoir. Commonly, flowing gas wells are adversely affected by accumulations within the well casing and tubing of liquids usually comprised of oil and salt water. As such fluids accumulate, the gas flow production of a well may diminish to the point of failure in consequence of the static pressure buildup within the tubing and/or casing. To achieve an optimization of the production from the well, therefore, the well operator is called upon to monitor pressure related parameters of this performance. Generally, any given well will exhibit its own unique performance "signature" which may itself vary with time.
A conventional approach for correcting for liquid build-up in a gas well involves a procedure referred to as "intermitting"; a cyclically performed operation wherein accumulated liquid is forced out of the well under gas pressure. In a typical intermitting procedure, mechanical clock-type controllers are provided which operate on a regular time cycle over repeating twenty-four hour intervals to periodically vent the well to the atmosphere and effect forcible expulsion of the liquid within the tubing string. Venting to the atmosphere now is considered disadvantageous both from an environmental standpoint as well as in consequence of the waste of valuable natural gas. As a consequence, other techniques now are generally employed. Another intermitting technique which has been utilized provides for the pressure monitoring of the tube string and casing of a given well. The system is based upon the observation that the appropriate time to clear a well can be determined by noting the differential in pressure between tubing and casing. This differential, in general, will represent the height of the fluid in the tubing above the bottom of the well. When the well monitors indicate that a predetermined differential in pressure is present, a motor valve is automatically opened to provide for fluid expulsion. See for example, U.S. Pat. No. 3,266,574. In another arrangement, for example as described in U.S. Pat. No. 3,863,714, a control is provided wherein the well is vented periodically in correspondence with the pressure within the tubing string. The output of the tubing string of the well is controlled by a motor valve, which in turn, is operated by pressure pilot valves responsive to the rate of flow and the differential existing between the sales and tubing lines to determine the producing interval.
In some geologic regions, for example in the Appalachian region, as well as regions in the Fort Worth basin, flowing gas wells are very difficult to produce. As a consequence, other techniques of production are required. For example, most such wells cannot merely be "intermitted," but must be produced on a cyclical basis. This technique involves a "shutting-in" procedure wherein the well is closed for a carefully determined interval of time sufficient to allow well pressure to build up sufficiently to expel all fluids upon subsequent opening up. Production only occurs during that relatively short interval wherein fluid and gas are expelled into the sales line system. The well then again is shut-in to achieve necessary pressure build-up. As is apparent, the timing of these operations is critical. For example, a typical well may produce for a twenty minute interval following which it must be shut-in for an interval of four hours. Because the duty cycle of the well is so short, deriving an optimum formula for producing it becomes a taxing endeavor. Many production parameters are considered, no two wells exhibiting the same performance signature. Particular note may be made of the economics associated with only minor changes in the production interval. For instance, a four minute deletion from a twenty minute production interval represents a 20% loss in sales revenue. Further, failure to shut-in such a well within mere minutes of the proper time envelope of production well may result in a complete loading up of the well. This represents a failure which may be very expensive to correct. One technique for correcting for "loading up" is to shut-in the well for an extended interval of time, e.g. 48 hours.
The tubing string in wells within the noted region generally incorporates a plunger lift device. With this arrangement, when the well is shut in, the plunger is situate in the lowermost portion of the tubing string. As gas pressure develops within the well during the shut-in interval, fluid accumulates in the tubing string above the plunger. At an optimum point in time, a motor valve coupled between the tubing string and separation and collection equipment is opened to permit the plunger to be propelled to the surface and fluid and gas which has collected above the plunger within the string is delivered into the sales system. Through the use of separation stages and the like, the liquid is segregated from the gas and the gas cap, for the production interval, is recovered. For the most part, control over these wells has been one based simply upon a somewhat crude clock-operated device, the cyclical closing and opening of a motor valve being determined by the operator following the periodic monitoring of a variety of parameters such as the differential pressure between casing and tubing string, sales line pressure, experience with adjacent wells, etc. With such monitoring, the signature of the well, i.e. the periodic development of pressure differentials optimum for producing and shutting in are determined and the clock controls are adjusted accordingly. Such periodic operation of the wells is found to be inadequate in many cases and the failure to accommodate for the various conditions which can exist for a given well may lead to a loading-up wherein expensive swabbing procedures and the like are required to clear the tubing. While the periodic shutting-in and opening of a well to produce it is desirable, the controllers available in the art exhibit many deficiencies by virtue of their incapability of responding to a broad variety of operational parameters. For example, it will be highly desirable to develop an easily adjusted on-off cycle accurate to within a minute which extends well beyond twenty-four hour intervals. Where conventional controllers are adjusted, for example, to operate at a 48 to 72 hour cycle, the incremental timing interval must be expanded accordingly to 4 or 6 minutes. The latter trade-off generally is considered unacceptable. Further, conditions often will be encountered where the cyclical timing system must be overridden and subsequently reinitiated on an automatic basis. For example, should the tubing pressure at the well head fall to a certain predetermined level an indication may be present that gas is not finding its way up through the tubing string and that liquid is building up. Accordingly, such a situation may represent an overriding condition calling for shutting in the well. Other conditions may relate to the safe operation of a gas production system. For example excessive liquid levels in separating systems will call upon an overriding of well cycling. Line pressure fluctuations may have a particularly deleterious effect upon the production of a well and production controls should be capable of monitoring for such conditions and reacting accordingly. In effect, a broad variety of conditions can be contemplated for monitoring and reaction to achieve the optimization as well as automation of flowing gas well production.